Natural gas which is produced from a natural gas well is typically separated and purified to provide products for a variety of end uses. The high-pressure mixture produced from the well, i.e. the wellstream, is typically sent to a separator vessel or a series of separator vessels maintained at progressively lower pressures where the wellstream is separated into a gaseous fraction and a liquid fraction.
The gaseous fraction leaving the separator, which may contain the impurities mercury, carbon dioxide and hydrogen sulfide, is sent to a gas treatment and purification plant where, typically, the mercury concentration is reduced to &lt;0.1 micrograms/m.sup.3, the CO.sub.2 concentration is reduced to the parts per million (ppm) level, and the H.sub.2 S to about one (1) ppm.
The purification of the gaseous fraction is commonly achieved by passing the gaseous fraction over a bed of activated carbon which has been impregnated with sulfur. In this step, the mercury in the gas reacts with the sulfur and is essentially removed from the gaseous fraction. Typically, the mercury content of the gas can be reduced from about 250 micrograms/m.sup.3 or higher to less than about 0.1 micrograms/m.sup.3.
The gas leaving the sulfur/carbon bed then could be treated with a hot aqueous potassium carbonate solution which has the ability to absorb CO.sub.2 and H.sub.2 S. This step produces a natural gas stream having a reduced CO.sub.2 and H.sub.2 S content. For example, the CO.sub.2 content of the gas can be reduced from about 15% to about 0.3% and the H.sub.2 S content from about 80 ppm to about 6 ppm.
The natural gas stream which resulted from treatment with the carbonate solution is further treated in order to reduce the amount of CO.sub.2 and H.sub.2 S by treating the gas with an amine solution, e.g. an aqueous solution of diethanolamine. Diethanolamine has the ability to absorb CO.sub.2 and H.sub.2 S, and can typically reduce the CO.sub.2 content from about 0.3% to about 50 ppm, and the H.sub.2 S content from about 6 ppm to about 1 ppm. The natural gas is then washed with water to remove traces of entrained amine. This water wash, however, neither removes residual mercury, typically present in levels of less than 0.1 .mu.g/Nm.sup.3, nor residual H.sub.2 S and CO.sub.2, typically about 1 ppmv and 50 ppmv, respectively.
The washed natural gas is water-saturated and has to be dried prior to liquefaction. Usually drying is achieved by contacting the wet gas with a desiccant in a packed bed specifically designed for this purpose. The desiccant bed undergoes repeated cycles of adsorption and regeneration. To ensure that the desiccant bed retains its integrity during the drying and regeneration cycles, a protective layer of inert alumina spheres having a depth of about 1-2 ft., and which are somewhat larger than the desiccant particles, is placed over the desiccant.
The dried gas, which still contains small amounts of mercury, CO.sub.2 and H.sub.2 S, can be further purified by contacting it with an adsorbent bed comprising sulfur on carbon, which has the ability to selectively remove mercury from the gas. Usually such an adsorbent can reduce the mercury concentration to less than 0.006 .mu.g/Nm.sup.3, however, including such an additional bed causes a pressure drop in the system. A pressure drop in a system in which an elevated pressure is required for the maximum efficiency of a process is not desirable.
Although the Hg content of the gas is reduced by the use of this additional adsorbent bed, its H.sub.2 S and CO.sub.2 content remain unchanged at about 1 and 50 ppmv respectively. In a liquefaction process, the temperature required to liquefy methane is 109.degree. K., i.e. -164.degree. C., which is well below the freezing point of CO.sub.2. Thus, in time, CO.sub.2 can accumulate in the cold parts of a liquefaction train and can cause plugging, an undesirable condition. Although H.sub.2 S is present in lesser amounts than the CO.sub.2, its freezing point, 187.degree. K., i.e. -86.degree. C., is also well above the 109.degree. K., which means that any H.sub.2 S in the gas will become a solid at the conditions of the liquefaction process which can add to the plugging problem.
It would be beneficial to provide a mechanism for further reducing the levels of residual mercury from the gas leaving the dessicant bed without a consequential pressure reduction which typically accompanies use of a second adsorbent bed. It would also be very desirable to remove CO.sub.2 and H.sub.2 S from that gas to reduce the risk of plugging.